Fracturing operations employing chlorine dioxide

ABSTRACT

A method includes introducing a treatment fluid into a wellbore penetrating a subterranean formation, the treatment fluid including a polymer gel having a water-soluble polymer, a proppant, and a polymer gel-preserving amount of chlorine dioxide, the placing step includes applying the treatment fluid at a sufficient pressure and at a sufficient rate to fracture the subterranean formation.

STATEMENT OF RELATED APPLICATIONS

This application claims priority to U.S. Provisional Application No.61/815,682 filed Apr. 24, 2013, the entire contents of which are herebyincorporated by reference in its entirety.

BACKGROUND

The present application relates to methods and compositions employedduring various stages of oil recovery from subterranean formations, andmore specifically to the use of chlorine dioxide in operations conductedthroughout the lifespan of an oil-bearing formation.

Over the course of the oil recovery cycle from an oil-bearing formation,various operations are performed to facilitate and increase oilrecovery. At the front end of the oil recovery cycle, access tooil-bearing strata may involve increasing the permeability of theformation through fracturing. In general, such treatments may beconducted by injecting a liquid, gas, or two-phase fluid down thewellbore at sufficient pressure and flow rate to fracture thesubterranean formation. A proppant material, such as sand, fine gravel,sintered bauxite, glass beads, or the like, may also be introduced intothe fractures to keep the fractures open after the fracturing pressureis released. Propped fractures provide larger flow channels throughwhich an increased quantity of a hydrocarbon may flow, therebyincreasing the productivity rate of the well. Fracturing fluids mayemploy polymer gel materials to enhance fluid viscosity to aid, interalia, proppant transport, adequate fracture propagation whilemaintaining sufficient fracture width to admit proppant, and to reducethe leakage rate of the fracturing fluid into the formation.

Because fracturing operations generally employ large volumes of water itmay be desirable, and even environmentally prudent, to employ anyproduced water, i.e. recovered water already present in the formation.Other produced waters that may be used include recycled water sources,such as waste water, and water from mining operations and landfillleachate. However, the use of produced water has been problematic duethe presence of contaminants which can impede the performance of thepolymer gels and viscosity reducers that are used in fracturing fluids.Many techniques have been developed to treat produced water so that itcan be used to formulate a competent fracturing fluid includingnano-filtration, electrocoagulation, and conventional filtration. Thesetechniques tend to be costly and may present practical limitations dueto their low throughput. For example, filtration rates may be so limitedthat there is an insufficient supply for continuous fracturing ratesabsent storing large volumes of fluid.

At the back end of the oil recovery cycle, operations have beendeveloped to increase the life span of well productivity. To maximizethe recovery of hydrocarbons from a reservoir, several methods may beimplemented after the natural depletion stage is over. Secondary methodsmay comprise water or gas injection to help maintain reservoir pressureand ensure hydrocarbon flow to the production wells. The recovery factorafter employing secondary methods often remains below 40% of the oiloriginally in place. At this point tertiary oil recovery methods maythen be employed to reach recovery factors above 60%.

Polymer flooding is one such tertiary method (though it may be employedearlier in the oil recovery cycle) applicable over a wide range ofreservoir conditions. In polymer flooding, a water-soluble polymer isdissolved in water to increase fluid viscosity typically forming apolymer gel which is introduced into the formation as a “slug,” orcontinuously. The goal of introducing the polymer is to improve thesweep efficiency through the hydrocarbon reservoir while increasingproduction fluid to the wellbore. In a typical polymer flood, polymer ismixed and injected over an extended period of time until at least about30% of the reservoir pore volume has been injected. When using a polymergel as a slug it is typically followed by water flooding to drive thepolymer gel and the oil bank in front of it toward the productionwellbore. Alternatively the polymer can be fed continuously to maintainviscosity in the injection fluid to increase sweep efficiency. As withfracturing, the volumes of fluids employed make it desirable to re-usethe aqueous portion recovered from the flooding process. However, theexposure of the polymer to the formation can sufficiently chemicallyalter the polymer making viscosity adjustment of the recovered aqueousfluids both necessary and material intensive, reducing theattractiveness of recycling the water phase in a cyclic floodingprocess. A further issue in a cyclic flooding process arises withrecycling of the polymer. Typically, the polymer ages as it passesthrough the formation and such aging can cause the polymer to gain anaffinity for hydrocarbons, making the separation of hydrocarbons fromthe polymer-laden fluid difficult.

Still further issues arise under certain formation conditions wherebythe polymer can inhibit flow through the formation via polymer pluggingof the injection wells, the formation, or both. One means to addresspolymer plugging employs concentrated chlorine dioxide solution todegrade the polymer. Other oxidants such as hydrogen peroxide, sodiumpersulfate, sodium hypochlorite, sodium peroxide, and sodium perboratehave also been used for this purpose. Polymer plugging notwithstanding,typically the bulk polymer gel slug “breaks through” to the producingwells in a short period of time. The polymer gel may then be brought tothe surface as part of the produced fluids. Typically the polymer gel isincorporated in an emulsion phase and a water phase of the producedfluids. While polymer gel capture in the produced fluids may bebeneficial from the perspective of maintaining formation integrity, thepresence of the polymer in production fluid can hamper separation ofwater and hydrocarbon. Additionally, the polymer gel present in producedfluids can plate out on production equipment, or “bake” on heatertreater surfaces requiring its manual removal.

SUMMARY

In some aspects, embodiments disclosed herein provide methods comprisingintroducing a treatment fluid into a wellbore penetrating a subterraneanformation, the treatment fluid comprising a polymer gel comprising awater-soluble polymer, a proppant, and a polymer gel-preserving amountof chlorine dioxide, wherein the placing step comprises applying thetreatment fluid at a sufficient pressure and at a sufficient rate tofracture the subterranean formation.

In some aspects, embodiments disclosed herein provide fracturing fluidscomprising a polymer gel comprising a water-soluble polymer, a polymergel-preserving amount of chlorine dioxide, a proppant, and an aqueousbase fluid.

Although the various steps of the method according to one embodiment ofthe invention are described in the above paragraphs as occurring in acertain order, the present application is not bound by the order inwhich the various steps occur. In fact, in alternative embodiments, thevarious steps can be executed in an order different from the orderdescribed above or otherwise herein.

DETAILED DESCRIPTION

Embodiments disclosed herein provide methods and compositions that mayfacilitate the use of polymer gels in various subterranean operations,including fracturing and polymer flooding applications. In particular,embodiments disclosed herein provide for the use of chlorine dioxide inconnection with both fracturing fluids/operations and as part of aqueousphase recycling in polymer flooding operations, while protecting againstdegradation of the polymer/polymer gel during such operations. This isin significant contrast to the recognized utility of chlorine dioxide asa reagent to degrade polymers employed during such operations.

In accordance with observations disclosed herein, it has been determinedthat a polymer gel's stability toward chlorine dioxide depends, at leastin part, on previous exposure to polymer gel-damaging reagents prior toexposure to chlorine dioxide. For example, a “virgin” sample ofpolyacrylamide (or similar polymers employed in polymer gels)i.e. notexposed to a formation or formation water, may be formulated into astable polymer gel, in the presence of excess residual chlorine dioxide.Such stability to chlorine dioxide is not observed with “aged” polymersthat may have been exposed to a formation or formation water, forexample. Such behavior of aged polymers is consistent with typical useof chlorine dioxide as a reagent to ameliorate formation polymerplugging. Without being bound by theory, it has been postulated thatlow-valent metal ions, which may be present in a formation or information water, especially in reducing formations such as those rich inhydrogen sulfide, may chemically alter the polymerand render itsusceptible to subsequent attack by chlorine dioxide.

Embodiments disclosed herein provide a means whereby treatment fluids,such as fracturing and/or polymer flooding fluids, may be formulatedwith produced water, although such fluids are not so limited by the useof such water sources. In particular, after exposure of produced waterto excess chlorine dioxide, it has been found that a stable polymer gelcan be prepared without the need for expensive and time consumingfiltration processes typically employed in the art. That is, it was notpreviously recognized that oxidized metal species, such as ferric ion(Fe(III)) are substantially innocuous to polymer gel stability. Thus,great time and expense was expended to rid formation water (or otherwater sources) of all iron and similar damaging metal ions, such asmanganese, nickel, lead, and tin. In accordance with embodimentsdisclosed herein, water sources containing low-valent metals (or evenabsent such metals) may be pre-treated with chlorine dioxide and used inunfiltered form to provide a stable polymer gel. The chlorine dioxideemployed may be used in sufficient excess to provide a treatment fluidwith biocidal capacity and/or to provide a degree of protection againstdamage upon exposure to a formation. Methods employing such treatmentfluids may also benefit from a pre-treatment of the formation withreagents to further protect the polymer gel from breakdown and thus,reduce formation plugging and equipment fouling. The treatment fluidsemployed in methods disclosed herein may be formulated on the fly orcontinuously at any desired flow rate, which may be particularlybeneficial in a fracturing operation.

Chlorine dioxide may also promote the separation of hydrocarbon fromwater, and facilitate direct treatment fluid reuse. As disclosed herein,a produced fluid from a polymer flood, for example, may be treated withchlorine dioxide enhancing hydrocarbon separation from water. Moreover,such treated water may be readily recycled in a cyclic flooding processby adding fresh polymer to the chlorine dioxide treated aqueous fractionto achieve a target viscosity. Advantageously, the amount of polymerneeded in a cyclic flooding process may be reduced by about 25% to about75%, providing a substantial materials cost savings in the overalloperation.

In some embodiments, there are provided methods comprising introducing atreatment fluid comprising a first polymer gel into a subterraneanformation to generate a production fluid comprising an aqueous portionand a hydrocarbon portion, treating the aqueous portion of theproduction fluid with chlorine dioxide to separate additionalhydrocarbons from the aqueous portion, and adjusting the viscosity ofthe treated aqueous portion prior to introducing the treated aqueousportion back into the subterranean formation.

Treatment fluids may be used in a variety of subterranean treatments. Asused herein, the term “treatment,” refers to any subterranean operationthat uses a fluid in conjunction with a desired function or purpose. Theterm “treatment,” does not imply any particular action by the fluid.Examples of common subterranean treatments include, without limitation,drilling operations, pre-pad treatments, fracturing operations,perforation operations, pre-flush treatments, after-flush treatments,sand control treatments (e.g., gravel packing), acidizing treatments(e.g., matrix acidizing or fracture acidizing), diverting treatments,cementing treatments, and wellbore clean-out treatments. For example, incertain fracturing treatments, generally a treatment fluid (e.g., afracturing fluid or a “pad fluid”) is introduced into a wellbore thatpenetrates a subterranean formation at a sufficient hydraulic pressureto create or enhance one or more pathways, or fractures, in thesubterranean formation. These cracks generally create a highlyconductive channel with deep reach into the reservoir, to improvehydrocarbon production and increase the “effective permeability” of thatportion of the formation. While some embodiments disclosed herein aredirected to such fracturing operations, treatment fluids disclosedherein may be used in any subterranean operation wherein a polymer gelor viscous fluid may be useful during the operation.

The term “gel,” and related terms such as “crosslinked gel,” or “polymergel,” as used herein, refers to a semi-solid, jelly-like state assumedby some colloidal dispersions. Polymer gels disclosed herein may beformed via hydration water-soluble polymers. The viscosity of such gelsmay be optionally altered by the presence of a crosslinking agent.

The term “production fluid,” as used herein refers to fluids that may berecovered from production wells or any recycled water sources such aswaste water or water from mine operation or landfill leachate. Suchfluids may include those generated by stimulation treatments, floodingtreatments, and the like. In particular embodiments, production fluidscomprise fluids recovered via polymer flooding operations. Productionfluids may comprise both hydrocarbons which are desired for recovery, aswell as other fluids, such as aqueous treatment fluids employed inconnection with stimulation/flooding operations.

In a flooding operation, methods disclosed herein may provide atreatment fluid comprising a first polymer gel wherein the treatmentfluid is introduced into a subterranean formation to generate aproduction fluid comprising an aqueous portion and a hydrocarbonportion. The production fluid may include some phase separation ofhydrocarbon and water. Where ready phase separation occurs, the bulk ofthe hydrocarbon layer may be skimmed off prior to any furthertreatments, although this is not necessary. After any optional skimming,methods disclosed herein may include treating the predominantly aqueousportion of the production fluid with chlorine dioxide to separateadditional hydrocarbons from the aqueous portion. In accordance withobservations disclosed herein, such additional hydrocarbon recovery maybe substantial, including as much as an additional about 20% hydrocarbontrapped in combined aqueous/emulsion phase. In a cyclic floodingprocess, where the water phase is recycled, methods disclosed herein mayinclude adjusting the viscosity of the treated aqueous portion prior tointroducing the treated aqueous portion back into the subterraneanformation.

In an exemplary embodiment, a produced fluid may be treated withsufficient chlorine dioxide to achieve a residual concentration of about0.1 to about 10 mg/L of ClO₂. The fluid may then be allowed to separateas it passes through a free water knock out, heater treater and/orstilling/skim tanks with oil being pulled off the top and solids off thebottom. A slip stream of chlorine dioxide treated aqueous layer may thenbe used to hydrate the polymer. The hydrated polymer can be added backto the main produced water stream with any make up water required.Overall, methods disclosed herein may provide increased oil recoveryfrom the produced fluids, higher efficiency of polymer performance andutilization, and minimization of formation damage.

In some embodiments, it may not be necessary to carry residual chlorinedioxide. That is, after a sufficient amount of chlorine dioxide has beenadded to effect phase separation, no further chlorine dioxide need beadded. Because the hydrocarbon content remaining in the aqueous phase isreadily quantified, one skilled in the art will be able to determine theamount of chlorine dioxide needed without leaving a significant amountof residual reagent.

In some embodiments, methods disclosed herein may further comprise astep of introducing a pre-treatment fluid in the subterranean formationprior to placing the treatment fluid in the formation, wherein thepre-treatment fluid comprises an oxidant. Pre-treatment fluids may beemployed to remove, or otherwise render innocuous, polymer damagingformation components. For example, a formation rich in iron, manganese,tin, and other low-valent metal ions may be pre-treated to deal withthese components. In some embodiments, a pre-treatment may be optionallyemployed for removal of the damaging components from the formation. Forexample, metal scavenging chelants may be employed to remove harmfulmetal ions. In some embodiments, pre-treatments may be used toameliorate the reducing capacity of the formation. For example, aformation rich in hydrogen sulfide may consume any residual protectivechlorine dioxide. A pre-treatment to neutralize or remove hydrogensulfide can help maintain the oxidized form of damaging metal ions wherehydrogen sulfide and other reducing agents may regenerate the low-valentoxidation states. A particular pre-treatment useful in connection withembodiments disclosed herein provides an oxidant such as described inU.S. Patent Application No. 2012/0244228, wherein the oxidant is addedin a treatment fluid entering the formation ahead of the polymer whereinthe oxidant specifically targets reduced metals and sulfides.

In some embodiments, the treatment fluid, especially those in a floodingoperation, may be introduced distal to a wellbore, while in otherembodiments the treatment fluid may be introduced through a portion ofthe wellbore itself. In a polymer flood for example, the treatment fluidcomprising the polymer gel may be introduced distal, i.e. about 30 feet,or about 20 feet or about 10 feet, or about 5 feet from the wellbore.One skilled in the art will appreciate that the exact distance from thewellbore that one may introduce a polymer gel as part of floodingoperation may depend on the various conditions of the formationincluding, inter alia, formation permeability, whether the formation hasundergone any previous stimulation or fracturing treatments, and thelike. One skilled in the art will also recognize that the effectivenessof moving the polymer out to farther distances from the wellbore mayrender the flood ineffective as it becomes more difficult to actuallypropagate the polymer through the formation. One of ordinary skill inthe art will be able to determine an appropriate distance at which apolymer gel slug may be introduced. In some embodiments, the location isthe same as where injection water is located.

In some embodiments, methods disclosed herein may further compriseperforming additional flooding operations selected from the groupconsisting of a gas flood, a wet acid gas flood, a caustic flood, asurfactant flood, a foam flood, a steam flood, a carbon dioxide, and awater flood. In some embodiments, a polymer flood may be performedbefore or after any of the aforementioned additional floodingoperations. In particular embodiments, a polymer flood may be followedby a water flood to push a polymer gel slug and any oil bank to berecovered toward the production well. In some embodiments, the polymerflood may be used in conjunction with a carbon dioxide flood. In someembodiments, the polymer flood may be used in conjunction with a carbondioxide and a surfactant flood.

In some embodiments, methods disclosed herein may further compriseseparating solids from the treated aqueous portion, i.e., after chlorinedioxide treatment. Numerous solids may drop out of hydrocarbon and/orwater phases upon treatment with chlorine dioxide. Such solids may beremoved by conventional techniques known to those skilled in the art,including filtration, floatation, gravimetric separation, skimming ofthe fluid layers, and the like.

In some embodiments, methods disclosed herein provide treatment fluidsthat comprise a polymer gel, which polymer gel comprises a water-solublepolymer class selected from the group consisting of a polyacrylate, apolyacrylamide, a cellulose, a xanthan gum, a guar gum, a diutan, awellan, a glucan, a glycan, a dextran, an alginate, a curdlan, apullulan, and combinations thereof and derivatives thereof. Anycompetent hydratable polymer capable of providing the requisiteviscosity/transport properties may be used. The water-soluble polymermay be naturally-occurring, synthetic, or a combination thereof. Thewater-soluble polymers also may be cationic, anionic, nonionic,amphoteric, or a combination thereof. Suitable polymers may include, butare not limited to, polysaccharides, biopolymers, and/or derivativesthereof that comprise one or more of monosaccharide units, such asgalactose, mannose, glucose, xylose, arabinose, fructose, glucuronicacid, or pyranosyl sulfate. Examples of suitable polysaccharidesinclude, but are not limited to, guar gum and derivatives (e.g.,underivatized guar, hydroxyethylguar, hydroxypropyl guar, carboxymethylguar, carboxymethylhydroxyethyl guar, and carboxymethylhydroxypropylguar (“CMHPG”)), cellulose derivatives (e.g., hydroxyethyl cellulose,carboxyethylcellulose, carboxymethylcellulose, andcarboxymethylhydroxyethyl cellulose), xanthan, scleroglucan, diutan,locust bean gum, tara, konjak, tamarind, starch, karaya, tragacanth andcarrageenan. Hydratable synthetic polymers and copolymers whichcomprise, for example, hydroxyl, cis-hydroxyl, carboxyl, sulfate,sulfonate, amino and/or amide functional groups may be suitable gellingagents. In some such embodiments, such polymers and copolymers maycomprise polyacrylate, polymethacrylate, polyacrylamide, maleicanhydride, methylvinyl ether polymers, polyvinyl alcohol andpolyvinylpyrrolidone. In particular, water-soluble polymers may beselected and/or synthetically designed based on (1) their ability toprovide targeted rheological properties, and (2) and their compatibilitywith chlorine dioxide.

In some embodiments, the water-soluble polymer is selected from thegroup consisting of polyacrylamide, partially hydrolyzed polyacrylamide,sulfonated polyacrylamide, methyl cellulose, hydroxyethylcellulose,hydroxypropyl cellulose, carboxymethylcellulose,carboxy-methylhydroxyethylcellulose, sulfonated carboxymethylcellulose,sulfonated carboxymethyl-hydroxyethylcellulose, sulfonatedhydroxyethylcellulose, sulfonated methylhydroxypropyl-cellulose,sulfonated methylcellulose, sulfonated ethylcellulose, sulfonatedpropylcellulose, sulfonated ethylcarboxymethylcellulose, sulfonatedmethylethylcellulose, sulfonated hydroxyl-propylmethylcellulose, guar,hydroxypropylguar, succinoglycan, scleroglucan, and combinationsthereof. In particular embodiments, fracturing and flooding operationsmay employ polyacryl-amides, partially hydrolyzed polyacrylamides,hydroxypropylguar, or hydroxyethylcellulose.

In some embodiments, the amount of water-soluble polymer employed in atreatment fluid used in a polymer flood may be in a range from about 10mg/L to 500 mg/L for friction reduction, including from about 25 mg/L to150 mg/L. In some embodiments, the amount of water soluble polymeremployed in a treatment fluid used in a polymer flood may be in a rangefrom about 500 mg/L to about 10,000 mg/L for viscosity modification,including from about 750 mg/L to about 2500 mg/L.

During flooding operations, in particular, the treatment fluid furthermay comprise chlorine dioxide at the beginning of the flooding cycle. Ina cyclic process, the produced fluids may be treated with an excess ofchlorine dioxide in each cycle, including the initial cycle. In someembodiments, the amount of chlorine dioxide in the treatment fluid atthe outset of a cyclic flooding cycle may be in a range from about 10parts per million to about 3,000 mg/L. The exact amount may depend onthe exact nature of the formation, including factors such as, interalia, the concentration of damaging components, both chemical andbiological (e.g. bacteria etc.). In some embodiments, the amounts ofchlorine dioxide needed may vary with each cycle as the remainingdamaging components in the formation may be sufficiently depleted inlater iterations.

In some embodiments, methods disclosed herein employ a treatment fluidwhich may comprise an aqueous base comprising production water, althoughas mentioned methods disclosed herein are not so limited. Thus,treatment fluids disclosed herein may comprise any base fluid. Typicallya base fluid will be aqueous based, although fracturing fluids, inparticular, are not so limited. Suitable base fluids for use in thetreatment fluids disclosed herein may comprise aqueous base fluids andnon-aqueous base fluids. Suitable aqueous base fluids that may be usedin the treatment fluids may include, without limitation, fresh water,salt water, brine, seawater, production water or any other aqueous fluidthat, preferably, does not adversely interact with the other componentsused in accordance with embodiments disclosed herein or with thesubterranean formation.

Aqueous base fluids present in the treatment fluids may be present in anamount sufficient to substantially hydrate the water-soluble polymer toform a gel, optionally in the presence of a crosslinking agent tomodulate viscosity. Suitable non-aqueous base fluids that may be used inthe treatment fluids may include glycerol, glycol, polyglycols, ethyleneglycol, propylene glycol, and dipropylenegylcol methyl ether. In someembodiments, the base fluid may be present in the treatment fluids ofthe present invention in an amount in the range from about 5% to 99.99%by volume of the treatment fluid.

In some embodiments, the base fluids suitable for use in the treatmentfluids may be optionally foamed (e.g., a liquid that comprises a gassuch as nitrogen or carbon dioxide). As used herein, the term “foamed”also refers to co-mingled fluids. In certain embodiments, it maydesirable that the base fluid is foamed to, inter alia, reduce theamount of base fluid that is required, e.g., in water sensitivesubterranean formations, to reduce fluid loss to the subterraneanformation, enhance flow back of fluids, and/or to provide enhancedproppant suspension. While various gases can be utilized for foaming thefracturing fluids, nitrogen, carbon dioxide, and mixtures thereof arecommonly employed in the art. In examples of such embodiments, the gasmay be present in a fracturing fluid in an amount in the range of fromabout 5% to about 98% by volume of the treatment fluid, or in the rangeof from about 20% to about 80%. The amount of gas to incorporate intothe fracturing fluid may be affected by factors including the viscosityof the fluid.

If desired, the treatment fluids may also be used in the form of anemulsion. An example of a suitable emulsion may comprise an aqueous basefluid comprising a gelling agent and a suitable hydrocarbon. In someembodiments, the emulsion may comprise about 30% of an aqueous basefluid and about 70% of a suitable hydrocarbon. In some embodiments, theexternal phase of the emulsion may be aqueous. In certain embodiments,it may be desirable to use an emulsion to, inter alia, reduce fluid lossto the subterranean formation, and/or to provide enhanced proppantsuspension. Other benefits and advantages to using emulsions in themethods employing the treatment and fracturing fluids will be evident toone of ordinary skill in the art.

The treatment fluids may vary widely in density. One of ordinary skillin the art with the benefit of this disclosure will recognize theparticular density that is most appropriate for a particularapplication. In some embodiments, the density of a non-foamed fracturingfluid may approximate the density of water. In other embodiments, thedensity of the non-foamed treatment fluids may range from about 8.3pounds per gallon to about 15 ppg. One of ordinary skill in the art withthe benefit of this disclosure will recognize that the density of anyparticular treatment fluid may also vary depending on the addition ofcertain additives, including, but not limited to, proppant, gas, fluidloss control additives, alcohols, glycols, and/or hydrocarbons.Furthermore, the desired density for a particular treatment fluid maydepend on characteristics of the subterranean formation, including,inter alia, the hydrostatic pressure required to control the fluids ofthe subterranean formation during placement of the fracture fluids, andthe hydrostatic pressure which will damage the subterranean formation.

In some embodiments, the treatment fluid may comprise a brine. Brinessuitable for use in some embodiments may include those that comprisemonovalent, divalent, or trivalent cations. Some divalent or trivalentcations, such as magnesium, calcium, iron, and zirconium, may, in someconcentrations and at some pH levels, cause undesirable crosslinking ofthe gelling agent. If a water source is used which contains suchdivalent or trivalent cations in concentrations sufficiently high to beproblematic, then such divalent or trivalent salts may be removed,either by a process such as reverse osmosis, or by raising the pH of thewater in order to precipitate out such salts to lower the concentrationof such salts in the water before the water is used. Another methodwould be to include a chelating agent to chemically bind the problematicions to prevent their undesirable interactions with the water solublepolymer. Suitable chelants include, but are not limited to, citric acidor sodium citrate. Other chelating agents also are suitable. Brines,where used, may be of any weight. Examples of suitable brines includecalcium bromide brines, zinc bromide brines, calcium chloride brines,sodium chloride brines, sodium bromide brines, potassium bromide brines,potassium chloride brines, sodium nitrate brines, sodium formate brines,potassium formate brines, cesium formate brines, magnesium chloridebrines, mixtures thereof, and the like. Additional salts may be added toa water source, e.g., to provide a brine, and a resulting viscosifiedtreatment fluid, having a desired density.

In some embodiments, methods disclosed herein employ treatment fluidfurther comprising any number of conventional additives known in theart. Such additives may be selected from the group consisting of acorrosion inhibitor, a pH control additive, a surfactant, a salt, abreaker, a fluid loss control additive, a scale inhibitor, an asphalteneinhibitor, a paraffin inhibitor, a biocide, a crosslinker, a fluidstabilizer, a chelant, a foaming agent, a defoamer, an emulsifier, ademulsifier, an iron control agent, an alcohol solvent, a mutualsolvent, an oxygen scavenger, a particulate diverter, a gas, a frictionreducer, an activator, a retarder, and combinations thereof.

In some embodiments, flooding methods disclosed herein may furthercomprise a step of removing production fluid from the wellbore prior tothe treating step with chlorine dioxide.

In some embodiments, it may be possible to treat production fluid insitu in the wellbore in the annular space via a sub pump or a rod pump.In some embodiments, the treating step may comprise adding an amount ofchlorine dioxide in a range from about 25 mg/L to about 500 mg/L. Insome embodiments, the additional hydrocarbons present in the aqueousportion which may be recovered may be up to about 20% by weight of theaqueous fraction and the treating step may reduce the hydrocarboncontent in the aqueous portion to less than about 2.5%, or to less thanabout 0.25%. After the treating step in a flooding operation, thetreated fluid may be subjected to a viscosity adjusting step whichcomprises forming a second polymer gel. The second polymer gel may bethe same or different from the first polymer gel. That is, afterretrieving additional hydrocarbons from the aqueous fraction of theproduction fluid, additional water soluble polymers may be added intothe treated aqueous fraction to adjust the viscosity for furtherflooding operations. In some embodiments, the amount of additionalwater-soluble polymers added after chlorine dioxide treatment issubstantially less than would be needed in a typical polymer floodrecycle. As mentioned herein above, this may be from about 25% to about75% reduction in the amount needed to achieve a target viscosity.

In some embodiments, there are provided treatment fluids comprising apolymer gel comprising a water-soluble polymer, a polymer gel-preservingamount of chlorine dioxide, and an aqueous base fluid. In some suchembodiments, the aqueous base fluid comprises production water. As usedherein, a “polymer gel-preserving amount” is an amount that accounts forany detrimental components present in the aqueous base fluid,detrimental components in the formation in which the treatment fluidwill be used, or both. For example, one can measure the quantities ofvarious damaging components in the aqueous base fluid and the formationin which the treatment fluid is to be used and estimate the amount ofchlorine dioxide needed to preserve the integrity of the water-solublepolymer and polymer gel. For example, the levels of iron, manganese, andother ions of interest may be measured. The treatment fluid may thenincorporate the polymer gel-preserving amount of chlorine dioxide as anamount sufficient to substantially oxidize reducing species present inthe treatment fluid. Such as the reducing species comprising lowoxidation state metal ions, hydrogen sulfide, and mixtures thereof. Inparticular, the levels of iron(II), manganese(II) and tin(II), and moregenerally, almost any of the reduced states of a transition metal. Inparticular embodiments, the treatment fluids may comprise a polymergel-preserving amount of chlorine dioxide that is also a biocidallyeffective amount. In some such embodiments, the biocidally effectiveamount of chlorine dioxide may comprise a residual amount in a rangefrom about 1 mg/L to about 10 mg/L. That is, enough chlorine dioxide isused to oxidize any low valent metals and still provide about 1 mg/L toabout 10 mg/L additional residual chlorine dioxide to maintain biocidalactivity. Additionally, the polymer gel-preserving amount of chlorinedioxide may be further adjusted to compensate for reducing speciespresent in a subterranean formation in which the treatment fluid is tobe employed. That is any reducing agent, such as hydrogen sulfide, whichmay be present in a formation which could reduce a transition metal tothe undesired low-valent form can be accommodated for by providing asufficient excess of chlorine dioxide.

In some embodiments, the treatment fluid is formulated particularly forpolymer flooding operations. In some embodiments, treatment fluids maybe formulated as fracturing fluids and as such further comprise aproppant. In particular embodiments, the treatment fluid disclosedherein may be used unfiltered. Proppants typically comprise particulatesolids. Examples of suitable proppants include without limitation, sand,bauxite, sintered bauxite, silica alumina, glass beads, ceramicmaterials, glass materials, polymer materials, polytetrafluoroethylenematerials, nut shell pieces, seed shell pieces, fruit pit pieces, wood,composite particulates, gravel, or combinations thereof. Generally, theparticulate solids may have a particle size in the range of from about 2to about 400 mesh, U.S. Sieve Series. In particular, the proppant mayhave a particle size in the range of from about 10 mesh to about 70mesh, U.S. Sieve Series. More particularly, the particle sizedistribution ranges of the proppant may be about 10 to about 20 mesh, 20to 40 mesh, 40 to 60 mesh or 50 to 70 mesh, depending on the particularsize and distribution of formation solids to be screened out by theparticulate solid pack. Although the proppant may be of any shape, theproppant generally may be spherical. However, proppants with otherparticulate solid shapes may also be utilized such as withoutlimitation, ellipsoidal, platelet-shaped, toroidal, oblate spheroids,prolate spheroids, scalene spheroids, rod-like, or combinations thereof.

In some embodiments, methods that employ fracturing fluids comprise aplacing step which involves applying the fracturing fluid at asufficient pressure and at a sufficient rate to fracture thesubterranean formation without causing substantial de-crosslinking.Thus, such methods may involve pumping the fracturing fluid (often as aslurry) at a pressure suitable for the conditions posed by the formationbeing fractured. Those skilled in the art will appreciate that anappropriate pressure and sufficient rate to fracture a subterraneanformation may depend on, inter alia, bottomhole conditions and thecompositional nature of the formation being fractured. For example, insome embodiments a sufficient pressure and a sufficient rate to fracturethe formation may comprise pressure in a range from about 300 to about20,000 psi and rates in a range of from about 10 bbl/minute to about 150bbl/minute. One skilled in the art will recognize that these figures aremerely exemplary approximations and factors such as permeability of theformation may play a role in selection of exact conditions to promotefracturing. Other factors which may impact the fracturing treatmentconditions (specifically impacting the fluid/slurry) include completiondimensions (inner diameter), perforation size, perforation density,cluster spacing of perforations, the presence of screens for sandcontrol, and the like. The exact selection of conditions for successfulfracturing may be aided by computational modeling of the formation.

In some embodiments, fracturing may be combined with gravel packingoperations in a process known in the art as frac-packing. In some suchembodiments, methods may include introducing a screen for gravel packingand a frac-packing fluid into the wellbore. Gravel packing is asand-control method used to prevent production of formation sand. Ingravel packing operations, a metallic or ceramic screen is placed in thewellbore and the surrounding annulus is packed with prepared gravel of aspecific size designed to prevent the passage of formation sand. Gravelpacking operations ideally stabilize the formation while causing minimalimpairment to well productivity. Suitable gravel packing fluids for usein conjunction with frac-packing, in particular, will be appreciated bythose skilled in the art.

In some embodiments, an optional chemical breaker may be included in thefracturing fluids disclosed herein which breaker acts on the polymer ofthe polymer gel. Suitable breakers may include any breaker that canreduce the viscosity of the fracturing fluid when desired and issuitable for use in the compositions and methods disclosed herein. Insome such embodiments, the breaker may comprise a delayed gel breakerthat will react with the fracturing fluid after a desired delay period.Suitable delayed gel breakers can be materials that are slowly solublein water, those that are encapsulated, or those that are otherwisedesigned to slowly solubilize in the fracturing fluid. In certainembodiments wherein these types of breakers are used, the breaking ofthe gel does not take place until the slowly soluble breakers are atleast partially dissolved in the water and this may be before or afterany de-crosslinking/pressure thinning. Breakers may include alkali metalcarbonates, alkali metal bicarbonates, alkali metal acetates, otheralkaline earth metal oxides, alkali metal hydroxides, amines, weak acidsand the like can be encapsulated with slowly water soluble or othersimilar encapsulating materials so as to make them act after a desireddelay period. Such materials are well known to those skilled in the artand may function to delay the breaking of the crosslinked gel for arequired period of time. Examples of water soluble and other similarencapsulating materials that may be suitable include, but are notlimited to, porous solid materials such as precipitated silica,elastomers, polyvinylidene chloride (PVDC), nylon, waxes, polyurethanes,polyesters, cross-linked partially hydrolyzed acrylics and the like. Incertain embodiments, when a polyvalent metal salt of an organophosphonicacid ester and an alkaline breaker are utilized, e.g., magnesium oxide,an initial increase in the viscosity of the fracturing fluid may beachieved, after which the gel may be further broken. If used, thedelayed gel breaker may be present in the fracturing fluid in an amountin the range of from about 0.01% to about 3% w/v, or in an amount in therange of from about 0.05% to about 1% w/v. “w/v” as used herein refersto the weight of the component based on the volume of the liquid that ispresent in the fracturing fluid.

In some embodiments, there are provided methods comprising introducing atreatment fluid into a wellbore penetrating a subterranean formation,the treatment fluid comprising a polymer gel comprising a water-solublepolymer, a proppant, and a polymer gel-preserving amount of chlorinedioxide, wherein the placing step comprises applying the treatment fluidat a sufficient pressure and at a sufficient rate to fracture thesubterranean formation.

Fracturing operations may be combined with gravel packing operations ina technique known as frac-packing, which combined operations aredesigned provide both a barrier to formation sand production as well asproppant flowback. In some embodiments, fracturing operations areconducted with a treatment fluid that comprises production water and apolymer gel-preserving amount of chlorine dioxide is an amountsufficient to substantially oxidize reducing species present in theproduction water. In some embodiments, the polymer gel-preserving amountof chlorine dioxide may be further adjusted by estimating the amount ofreducing species present in the subterranean formation being fractured.In some embodiments, iron (III) ions are present in the fracturing fluidwhen initially formulated and remain in the treatment fluid during theintroducing step. That is, there is no need to remove iron (III) orother oxidized metals when employing treatment fluids disclosed herein,especially when excess residual chlorine dioxide is employed.

A flooding or fracturing operation may include introducing a treatmentfluid, according to embodiments disclosed herein, into a subterraneanformation. Other operations which indicate the use of polymer gelcompositions may be performed with substantially similar treatmentfluids. Such operations may include fluid loss treatments, divertingoperations, and the like. Further, any of the methods disclosed hereinmay be performed in a wellbore that is vertical, horizontal, ordeviated. In some embodiments, a wellbore may comprise a combination ofvertical horizontal and deviated portions. In some embodiments, methodsdisclosed herein may be performed in a subterranean formation that isoffshore.

To facilitate a better understanding of the present embodiments, thefollowing Examples are provided. In no way should the following Examplesbe read to limit, or to define, the scope of the embodiments disclosedherein.

Example 1

This Example shows the recovery of additional hydrocarbon by treatmentof produced fluid with chlorine dioxide.

A sample of produced fluid from a polyacrylamide polymer flood that hadbeen in operation for over 12 months that was taken downstream of thewater knockout and was tested by thermal separation (retort). The fluidwas found to contain 16% by weight petroleum hydrocarbon 2% by weightinsoluble solids with the remainder being water. Portions of the samplewere treated with 25, 50, 75, and 100 mg/L chlorine dioxide. All samplestreated with chlorine dioxide exhibited a clean hydrocarbon water breakwithin five minutes. The samples were further analyzed to determinehydrocarbon content. At the 100 ppm dosage of chlorine dioxide the waterlayer was determined to contain less than 0.25% hydrocarbon. At 25, 50,and 75 mg/L chlorine dioxide dosage the water was found to contain 2.5%,2.1% and <0.25% hydrocarbon, respectively.

Example 2

This Example shows the reduction in viscosity of produced fluid upontreatment with chlorine dioxide.

Untreated sample from Example 1 was examined using a Brookfieldviscometer to determine the viscosity of the fluid. The samples of thechlorine dioxide treated fluid were also examined. The results are shownin Table 1.

TABLE 1 Viscosity @ 20 c +/− 3 cp Treatment 6 RPM 12 RPM 30 RPM 60 RPMuntreated 170 cp 165 cp 148 cp >100 cp maxed full out  25 ppm 4 10 8 10 50 ppm 4 5 6 7  75 ppm 6 7 8 8 100 ppm 6 6 5 6

Chlorine dioxide treatment reduced the viscosity of the resultant fluidby greater than 90 percent.

Example 3

This Example shows the adjustment of the viscosity of the water layerfrom Example 1.

The water layers from the solutions in Example 1 were treated withpolyacrylamide polymer. The polymer was hydrated at concentrations of1500, 2000, and 2500 mg/L and compared to an untreated sample withrespect to viscosity. Referring to Table 2, the fluid that was treatedwith chlorine dioxide resulted in a far superior polymer hydration tothe untreated fluid. In the chlorine dioxide treated fluid less than 50%of the polymer was required to achieve similar viscosities when comparedto the fluid that was not treated by chlorine dioxide.

TABLE 2 Viscosity with polymer@ 20 c +/− 3 cp ClO₂ 6 rpm 12 rpm 30 rpm60 rpm ppm Polymer Viscosity Viscosity Viscosity Viscosity 10 1500 125100 78 59 10 2000 223 175 112 84 10 2500 362 249 153 Max 25 1500 117 10369 59 25 2000 242 188 130 97 25 2500 396 301 191 Max 50 1500 108 95 6951 50 2000 209 159 112 87 50 2500 351 272 178 Max 75 1500 122 98 68 5875 2000 211 151 101 75 75 2500 361 346 Max Max 0 1500 37 36 29 36 0 200072 68 56 51 0 2500 143 119 99 98 50 300 20 18 17 19 50 400 18 18 16 1750 500 25 24 22 20 50 600 27 25 22 24 50 700 37 34 32 30 50 800 42 35 3432 50 900 58 56 49 39

Example 4

This Example shows improved recovery of hydrocarbon from produced fluidupon treatment with chlorine dioxide.

A produced fluid from a polyacrylamide polymer flood was treated with400 mg/L chlorine dioxide. Prior to treatment the fluid contained about15% by volume hydrocarbon; sand and other solids approximating 10% withthe remainder consisting of brine. Prior to treatment with chlorinedioxide the fluid was predominantly homogeneous. After treatment withchlorine dioxide the fluid broke into distinct layers. Approximately 65%of the hydrocarbon was recoverable by skimming in stilling tanks.Approximately 90% of the solids settled out of the water phase. Allsulfides were eliminated from all phases of the fluid stream.

Example 5

This Example shows the improved gel performance of chlorine dioxidetreated water compared to untreated water.

Polymer was added to the untreated fluid and the water portion of thetreated fluid from Example 4. It should be noted that the water layerfrom the treated fluid still contained about 4% highly emulsifiedhydrocarbon. The polyacrylamide polymer was added to each of the fluidsas indicated in the data in Table .

TABLE 3 Polymer Concentration (ppm) Viscosity (cP) Untreated producedwater 1 1500 26 2 2000 50.5 3 2500 86 Treated with chlorine dioxide (400mg/L) 4 1500 47 5 2000 78.5 6 2500 200

The results demonstrate a 50 to 200% increase in performance of thepolymer for viscosity increase in the fluid that has been treated withchlorine dioxide.

Example 6

This Example shows general conditions for preparing hydrated polymersamples.

A sample of a polyacrylamide polymer was hydrated in deionized water. Inthis and the following Examples the polymer was hydrated by gentlemixing at approximately 100 RPM in a low sheer mixer. The viscosity ofthe hydrated polymer was determined using a Brookfield viscometer. Theviscosity of the resulting product was determined to be 730 centipoises.As with all following Examples the viscosity was determined at 74 ° F.and a final Solution pH of between 7.1 and 7.4.

Example 7

This Example shows the effect of iron(II) on the viscosity ofpolyacrylamide polymer.

20 mg/L of iron (II)chloride was added to a sample and deionized waterand 1500 mg/L of a polyacrylamide polymer and allowed to hydrate. Theresulting solution was analyzed using a Brookfield viscometer and theviscosity of the solution was determined to be less than 15 centipoises.

Example 8

This Example shows the effect of iron(III) on the viscosity ofpolyacrylamide polymer.

20 mg/L of iron (III) chloride was added to deionized water along with1500 mg/L of a polyacrylamide polymer and allowed to hydrate. Theresultant solution was analyzed using a Brookfield viscometer. Theresultant solution had a viscosity of 750 centipoises.

Examples 7 and 8 indicate that ferrous ion (Fe(II)) is responsible forpolymer degradation, while ferric ion (Fe(III)) is relatively innocuous.Thus, the presence of ferric ion is apparently not detrimental to thestability of the polymer gel. This observation indicates that the costlyand tedious filtration normally employed to remove iron after oxidationand flocculation is unnecessary.

Example 9

This Example shows the effect of chlorine dioxide treatment on viscosityin the presence of iron (II).

50 mg/L of chlorine dioxide, 20 mg/L iron (II) chloride and 1500 mg/L ofa polyacrylamide polymer was added to a solution in deionized water. Thepolymer was allowed to hydrate and was analyzed with a Brookfieldviscometer. The solution was determined to have a viscosity of 420centipoises.

Example 10

This Example shows the preparation of a treatment fluid in the absenceof iron salts at 50 mg/L chlorine dioxide.

50 mg/L of chlorine dioxide was added to deionized water along with 1500mg/L of a polyacrylamide polymer. The polymer was allowed to hydrate.The viscosity of the resulting solution was determined using aBrookfield viscometer. The solution was determined to have a viscosityof 460 centipoises.

Example 11

This Example shows the preparation of a treatment fluid in the absenceof iron salts at 100 mg/L chlorine dioxide.

100 mg/L of chlorine dioxide was added to deionized water with 1500 mg/Lof a polyacrylamide polymer. The polymer was allowed to hydrate. Theresultant solution was analyzed using a Brookfield viscometer. Theresulting viscosity of the solution was 440 centipoises.

Example 12

This Example shows the preparation of a treatment fluid in the absenceof iron salts at 150 mg/L chlorine dioxide.

150 mg/L of chlorine dioxide was added to deionized water along with1500 mg/L of a polyacrylamide polymer. The solution was allowed tohydrate and then analyzed using a Brookfield viscometer. The resultantsolution had a viscosity of 580 centipoises.

Example 13

This Example shows the preparation of a treatment fluid in the absenceof iron salts at 200 mg/L chlorine dioxide.

200 mg/L of chlorine dioxide was added to deionized water along with1500 mg/L of a polyacrylamide polymer. The polymer was allowed tohydrate. The resulting solution was tested with a Brookfield viscometerand determined to have a viscosity of about 490 centipoises.

Example 14

This Example shows the formation of a treatment fluid from productionwater without chlorine dioxide treatment.

A sample of typical Permian basin produced water was obtained. The waterwas analyzed and determined to contain 25 mg/L of iron as iron two andvarious other metals. 1500 mg/L of a polyacrylamide polymer was added tothe solution. The polymer was allowed to hydrate. The viscosity of thesolution was determined using a Brookfield viscometer. The resultingsolution had a viscosity of 12 centipoises.

Example 15

This Example shows the formation of a treatment fluid from productionwater with prior chlorine dioxide treatment.

An identical sample as Example 14 was prepared, with the exception thatprior to addition of the polymer, 50 mg/L of chlorine dioxide was addedand allowed to react for five minutes. The solution had a residual ofapproximately 20 mg/L chlorine dioxide. After the polymer hydrated thefluid was tested with the Brookfield viscometer and it was determinedthat the fluid had a viscosity of 430 centipoises.

Example 16

This Example shows the formation of a treatment fluid from productionfluid without chlorine dioxide treatment. Production fluid includes iron(II) and hydrocarbons.

A sample of a typical Permian basin produce fluid was tested anddetermined to contain 45 mg/L of iron as iron (II) and 320 mg/L totalpetroleum hydrocarbons. The solution was treated with 50 mg/L chlorinedioxide and allowed to react for five minutes. The chlorine dioxideresidual was determined to be 12 mg/L. 1500 mg/L of a polyacrylamidepolymer was added to the treated solution. The polymer was allowed tohydrate. The resulting solution was tested by a Brookfield viscometerand determined to have a viscosity of 390 centipoises.

Example 17

This Example shows the formation of a treatment fluid from productionwater from a water flood.

Samples of produced water from an intermediate crude water flood thatcontained approximately 15 mg/L iron (II)were dosed with 1500 mg/L, 2000mg/L and 2500 mg/L of a polyacrylamide polymer and allowed to hydrate.The samples were tested with a Brookfield viscometer and found to haveviscosities of 26 cP, 50.5 cP and 86 cP, respectively. An identicalgroup of samples were treated with 50 mg/L of chlorine dioxide and dosedwith the same levels of polymer. The samples were analyzed with aBrookfield viscometer and found to have viscosities of 47cP, 78.5 cP,and 200 cP, respectively.

Example 18

This Example shows the formation of a treatment fluid from productionwater with hydroxypropyl guar as the water-soluble polymer.

A sample of Permian produced water that contained approximately 82 mg/Lof iron II and 26 mg/L sulfide was dosed with 5000 mg/L ofhydroxypropylguar (HPG). The mixture was allowed to hydrate and analyzedby a Brookfield viscometer. The resultant viscosity was about 16 cP. Asample of the same fluid was dosed with 150 mg/L chlorine dioxide andallowed to react for 15 minutes. The resultant solution had a residualof 6 mg/L chlorine dioxide. 5000 mg/L of HPG was added to the treatedsample and allowed to hydrate. The resultant mixture was analyzed byBrookfield viscometer and found to have a viscosity of 107 cP.

Example 19

This Example shows the formation of a treatment fluid from productionwater with hydroxyethyl cellulose (HEC) as the water-soluble polymer.

A sample of Permian produced water that contained approximately 82 mg/Lof iron II and 26 mg/L sulfide was dosed with 5000 mg/L ofhydroxyethylcellulose (HEC). The mixture was allowed to hydrate andanalyzed by a Brookfield viscometer. The resultant viscosity was 12 cP.A sample of the same fluid was dosed with 150 mg/L chlorine dioxide andallowed to react for 15 minutes. The resultant solution had a residualof 6 mg/L chlorine dioxide. 5000 mg/L of HEC was added to the treatedsample and allowed to hydrate. The resultant mixture was analyzed byBrookfield viscometer and found to have a viscosity of 147 cP.

Example 20

This Example shows the recovery of additional hydrocarbon by treatmentof produced fluid with chlorine dioxide.

A sample of produced fluid from a polyacrylamide polymer flood that hadbeen in operation for over 36 months that was taken downstream of thewater knockout and was tested by thermal separation (retort). The fluidwas found to contain 11% by weight petroleum hydrocarbon 2% by weightinsoluble solids with the remainder being water and soluble salts.Portions of the sample were treated with 25, 50, 75, and 100 mg/Lchlorine dioxide. All samples treated with chlorine dioxide exhibited aclean hydrocarbon water break within 30 seconds to five minutes. Thesamples were further analyzed to determine hydrocarbon content. At the100 ppm dosage of chlorine dioxide the water layer was determined tocontain less than 0.25% hydrocarbon. At 10, 25, 50, and 75 mg/L chlorinedioxide dosage the water was found to contain 4.2, 2.5%, <0.25% and<0.25% hydrocarbon, respectively.

Example 21

This Example shows the reduction in viscosity of produced fluid upontreatment with chlorine dioxide.

Untreated sample from Example 20 was examined using a Brookfieldviscometer to determine the viscosity of the fluid. The samples of thechlorine dioxide treated fluid were also examined. The results are shownin Table 21-1.

TABLE 21-1 Viscosity @ 20 c +/− 3 cp Treatment 6 RPM 12 RPM 30 RPM 60RPM untreated 182 cp 177 cp 158 cp >100 cp maxed full out  25 ppm 4 9 1022  50 ppm 5 6 7 13  75 ppm 7 7 8 6 100 ppm 6 8 6 9

Chlorine dioxide treatment reduced the viscosity of the resultant fluidby greater than 90 percent.

Example 22

This Example shows the adjustment of the viscosity of the water layerfrom Example 20.

The water layers from the solutions in Example 1 were treated withpolyacrylamide polymer. The polymer was hydrated at concentrations of1500, 2000, and 2500 mg/L and compared to an untreated sample withrespect to viscosity. Referring to Table 22-2, the fluid that wastreated with chlorine dioxide resulted in a far superior polymerhydration to the untreated fluid. In the chlorine dioxide treated fluidless than 40% of the polymer was required to achieve similar viscositieswhen compared to the fluid that was not treated by chlorine dioxide.

TABLE 22-2 Viscosity with polymer@ 20 c +/− 3 cp ClO₂ 6 rpm 12 rpm 30rpm 60 rpm ppm Polymer Viscosity Viscosity Viscosity Viscosity 10 1500132 106 88 68 10 2000 228 181 126 89 10 2500 360 258 165 Max 25 1500 117101 74 63 25 2000 244 189 137 102  25 2500 404 298 198 Max 50 1500 10797 74 54 50 2000 210 157 113 89 50 2500 352 274 180 Max 75 1500 125 10468 63 75 2000 213 159 108 79 75 2500 369 356 Max Max 0 1500 22 21 18 170 2000 31 26 22 19 0 2500 110 94 92 90 50 300 23 21 19 17 50 400 25 2322 19 50 500 32 29 27 25 50 600 37 35 34 31 50 700 44 39 39 37 50 800 5255 54 47 50 900 63 59 56 52

Example 23

This Examples shows the effects of chlorine dioxide on viscosity in thepreparation of exemplary fluids that can be used in fracturingoperations.

A brine solution was prepared using a mixture of fresh surface water andproduced water resulting in a fluid containing approximately 18,000 mg/Las chlorides, 11 mg/L of iron as Fe (II), and other ionic components astypical of the region used in mixed fluid fracturing operations. Thefluid was evaluated at three different dosages of hydroxypropyl guar at4 minute and 15 minute hydration times. This was compared to theidentical fluid being treated with chlorine dioxide at a dose of 25 mg/Limmediately prior to hydration the. Referring to table 23-1,pretreatment of the fluid with chlorine dioxide prior to theintroduction results in an average increased viscosity of over 160%. Bycomparison, treatment of the fluid after hydration results in a slightdecrease of viscosity from the untreated baseline.

TABLE 23-1 Viscosity ClO₂ ClO₂ HPG 6 12 30 60 Delta Dose resid.Hydration Dose rpm rpm rpm rpm Avg. Temp. efficany (mg/L) (mg/L) (min)(mg/L) (cp) (cp) (cp) (cp) (cp) pH (F. °) (%) 0 0 15 1000 15 10 6.5 6.69.5 7.7 70 N/A 0 0 15 1500 15 10.75 9.4 9.3 11.1 7.8 71 N/A 0 0 15 200036 25.5 21.4 20.1 25.8 7.7 70 N/A 0 0 4 1000 39 26 14.8 12.2 23.0 7.8 71N/A 0 0 4 1500 49 28.75 17.7 15.2 27.7 7.8 72 N/A 0 0 4 2000 43 25 18.215.5 25.4 7.8 71 N/A 25 1.1 15 1000 15 15 12.8 12.3 13.8 7.6 71 145% 251.5 15 1500 37.5 27.5 20 16.5 25.4 7.6 70 200% 25 0.9 15 2000 57.5 42.533 30 40.8 7.6 70 158% 25 2.1 4 1000 65 38.75 21 15.1 35.0 7.4 70 152%25 1.8 4 1500 67.5 41.25 25.5 19.8 38.5 7.6 69 139% 25 1.6 4 2000 8048.75 31.5 25 46.3 7.4 70 184%

Although the invention has been described in detail for the purpose ofillustration based on what is currently considered to be the mostpractical and preferred embodiments, it is to be understood that suchdetail is solely for that purpose and that the invention is not limitedto the disclosed embodiments, but, on the contrary, is intended to covermodifications and equivalent arrangements that are within the spirit andscope of the appended claims. For example, it is to be understood thatthe present invention contemplates that, to the extent possible, one ormore features of any embodiment can be combined with one or morefeatures of any other embodiment.

Furthermore, since numerous modifications and changes will readily occurto those of skill in the art, it is not desired to limit the inventionto the exact construction and operation described herein. Accordingly,all suitable modifications and equivalents should be considered asfalling within the spirit and scope of the invention.

What is claimed is:
 1. A method comprising: introducing a treatmentfluid into a wellbore penetrating a subterranean formation, thetreatment fluid comprising: a polymer gel comprising a water-solublepolymer; a proppant; and a polymer gel-preserving amount of chlorinedioxide; wherein the placing step comprises applying the treatment fluidat a sufficient pressure and at a sufficient rate to fracture thesubterranean formation.
 2. The method of claim 1, wherein the treatmentfluid comprises production water.
 3. The method of claim 1, wherein thepolymer gel-preserving amount of chlorine dioxide is an amountsufficient to substantially oxidize reducing species present in thetreatment fluid.
 4. The method of claim 3, wherein the reducing speciescomprises low oxidation state metal ions, hydrogen sulfide, and mixturesthereof.
 5. The method of claim 4, wherein the low oxidations statemetal ions comprise iron (II) ions.
 6. The method of claim 1, whereinthe polymer gel-preserving amount of chlorine dioxide is also abiocidally effective amount.
 7. The method of claim 6, wherein thebiocidally effective amount of chlorine dioxide comprises a range fromabout 1 to about 10 mg/L.
 8. The method of claim 1, wherein the polymergel-preserving amount of chlorine dioxide is further adjusted byestimating the amount of reducing species present in the subterraneanformation being fractured.
 9. The method of claim 1, wherein iron (III)ions are present in the treatment fluid and remain in the treatmentfluid during the introducing step.
 10. A fracturing fluid comprising: apolymer gel comprising a water-soluble polymer; a polymer gel-preservingamount of chlorine dioxide; a proppant; and an aqueous base fluid. 11.The fracturing fluid of claim 10, wherein the aqueous base fluidcomprises production water.
 12. The fracturing fluid of claim 10,wherein the polymer gel-preserving amount of chlorine dioxide is anamount sufficient to substantially oxidize reducing species present inthe fracturing fluid.
 13. The fracturing fluid of claim 12, wherein thereducing species comprises low oxidation state metal ions, hydrogensulfide, and mixtures thereof.
 14. The fracturing fluid of claim 13,wherein low oxidation state metal ions comprise iron (II) ion.
 15. Thefracturing fluid of claim 10, wherein the polymer gel-preserving amountof chlorine dioxide is also a biocidally effective amount.
 16. Thefracturing fluid of claim 15, wherein the biocidally effective amount ofchlorine dioxide comprises a residual amount in a range from about 1mg/L to about 10 mg/L.
 17. The fracturing fluid of claim 10, wherein thepolymer gel-preserving amount of chlorine dioxide is further adjusted tocompensate for reducing species present in a subterranean formation inwhich the fracturing fluid is to be employed.
 18. The fracturing fluidof claim 10, wherein the fracturing fluid is formulated for polymerflooding operations.
 19. The fracturing fluid of claim 10, wherein thewater-soluble polymer comprises a polymer selected from the groupconsisting of a polyacrylamide, a cellulose, a guar, and combinationsthereof.
 20. The treatment fluid of claim 10, further comprising anadditive selected from the group consisting of a corrosion inhibitor, apH control additive, a surfactant, a salt, a breaker, a fluid losscontrol additive, a scale inhibitor, an asphaltene inhibitor, a paraffininhibitor, a further biocide, a crosslinker, a fluid stabilizer, achelant, a foaming agent, a defoamer, an emulsifier, a demulsifier, aniron control agent, an alcohol solvent, a mutual solvent, an oxygenscavenger, a particulate diverter, a gas, a friction reducer, anactivator, a retarder, and combinations thereof.